Methods useful for controlling fluid loss in subterranean formations

ABSTRACT

Methods of controlling fluid loss in a subterranean formation comprising: providing a treatment fluid comprising an aqueous fluid and a fluid loss control additive comprising a water-soluble polymer having hydrophobic or hydrophilic modification; introducing the treatment fluid into an interval of a well bore, the well bore penetrating the subterranean formation; creating one or more perforations in the interval of the well bore, wherein the perforations extend from the well bore and into the subterranean formation; and allowing the treatment fluid to contact a portion of the subterranean formation through the one or more perforations. Methods of a reducing fluid loss from a perforated and/or gravel packed interval of a well bore using a fluid loss control additive comprising a water-soluble polymer having hydrophobic or hydrophilic modification.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation-in-part of U.S. application Ser. No.11/102,062 filed on Apr. 8, 2005, which is a continuation-in-part ofU.S. application Ser. No. 10/881,198 filed on Jun. 29, 2004 now U.S.Pat. No. 7,117,942 and U.S. patent application Ser. No. 10/760,443 filedon Jan. 20, 2004 now U.S. Pat. No. 7,759,292, which is acontinuation-in-part of U.S. application Ser. No. 10/440,337 filed onMay 16, 2003 now abandoned, and U.S. application Ser. No. 10/612,271filed on Jul. 2, 2003 now U.S. Pat. No. 7,812,136, the entiredisclosures of which are incorporated by reference.

BACKGROUND

The present invention relates to fluid loss control and, moreparticularly, to using fluid loss control additives that comprise awater-soluble polymer having hydrophobic or hydrophilic modification.

A problem often encountered during subterranean treatments is theundesired loss or leak off of fluid into the formation. This undesiredloss or leak off is commonly referred to as “fluid loss.” Fluid loss canoccur in drilling operations, cleanup operations, workover operations,completion operations, stimulation treatments (e.g., fracturing,acidizing), and sand control treatments (e.g., gravel packing). Infracturing treatments, fluid loss into the formation may result in areduction in fluid efficiency, such that the fracturing fluid cannotpropagate the fracture as desired. As used herein, the term “treatment,”or “treating,” refers to any subterranean treatment that uses a fluid inconjunction with a desired function and/or for a desired purpose. Theterm “treatment,” or “treating,” does not imply any particular action bythe fluid or any particular component thereof.

Fluid loss into the formation may result from a number of downholeconditions, such as high-formation permeability, overbalance pressures,perforated or open-hole intervals in the well bore, and largedifferential pressures associated with differential segregation in wellscompleted in a multilayer reservoir. In some instances, the fluid lossmay be into a low-pressure portion of the formation due to overbalancepressures, for example, where a well is completed in a multilayerreservoir.

Traditional methods of combating fluid loss may involve mechanical orchemical isolation of the portions of the subterranean formation intowhich fluid loss occurs. However, in certain subterranean treatments(e.g., workover operations), the mechanical completion itself may notallow for such isolation to occur. In some instances, the use oflow-density fluids, such as hydrocarbon-based fluids or foamed fluids,may be used to combat fluid loss into the formation. However, in someinstances, well conditions may not allow for the use ofhydrocarbon-based fluids, for instance, due to the hydrostatic pressuresassociated with the hydrocarbon-based fluids. Furthermore, the use offoamed fluids may add undesired expense and complexity to the well borecleanup operation, as well as additional safety considerations.

In other instances, to prevent fluid loss from occurring, fluid losscontrol additives commonly may be included in the treatment fluids.Examples of commonly used fluid loss control additives include, but arenot limited to, gelling agents, such as hydroxyethylcellulose andxanthan. Additional fluid loss control may be provided by crosslinkingthe gelling agent or by including fluid loss control materials, such assized solids (e.g., calcium carbonate), silica particles, oil-solubleresins, and degradable particles, in the treatment fluids. The fluidloss control materials may be used in combination with or separatelyfrom the conventional fluid loss control additives. These conventionalmethods commonly work at the well bore and/or formation face and if theyinvade the reservoir, formation damage may occur. Additionally, the useof crosslinked fluids may impact fracture geometry, for example,creating wider, shorter fractures. Further, the crosslinked fluids mayform a filter cake, which may be detrimental to the production ofreservoir fluids.

Chemical fluid loss control pills also may be used to combat fluid loss.Conventional chemical fluid loss control pills may be characterized aseither solids-containing pills or solids-free pills. Examples ofsolids-containing pills include sized-salt pills and sized-carbonatepills. These solids-containing pills often are not optimized for theparticular downhole hardware and conditions that may be encountered. Forinstance, the particle sizes of the solids may not be optimized for aparticular application and, as a result, may increase the risk ofinvasion into the interior of the formation matrix, which may greatlyincrease the difficulty of removal by subsequent remedial treatments.Additionally, high-solids loading in the pills, in conjunction with thelarge volumes of these pills needed to control fluid losses, may greatlyincrease the complexity of subsequent cleanup. Furthermore, high loadingof starches and biopolymers in the sized salt pills may add to thedifficulty of cleanup either by flow back or remedial treatments.Solids-free fluid loss control pills commonly comprise hydrated polymergels that may not be effective without some invasion into the formationmatrix. These pills typically require large volumes to control fluidloss and remedial treatments to remove.

Once fluid loss control is no longer required, for example, aftercompleting a treatment, remedial treatments may be required to removethe previously placed pills, for example, so that the wells may beplaced into production. For example, a chemical breaker, such as anacid, oxidizer, or enzyme may be used to either dissolve the solids orreduce the viscosity of the pill. In many instances, however, use of achemical breaker to remove the pill from inside the well bore and/or theformation matrix may be either ineffective or not a viable economicoption. For example, due to production equipment in the well bore,uniform placement of the breaker into the portion of the formationtreated with the pill may not be possible. Furthermore, the chemicalbreakers may be corrosive to downhole tools. Additionally, as thechemical breakers leak off into the formation, they may carryundissolved fines that may plug and/or damage the formation or mayproduce undesirable reactions with the formation.

SUMMARY

The present invention relates to fluid loss control and, moreparticularly, to using fluid loss control additives that comprise awater-soluble polymer having hydrophobic or hydrophilic modification.

An embodiment of the present invention is a method of controlling fluidloss in a subterranean formation comprising: providing a treatment fluidcomprising an aqueous fluid and a fluid loss control additive comprisinga water-soluble polymer having hydrophobic or hydrophilic modification;introducing the treatment fluid into an interval of a well borepenetrating the subterranean formation; creating one or moreperforations in the interval of the well bore, wherein the perforationsextend from the well bore and into the subterranean formation; andallowing the treatment fluid to contact a portion of the subterraneanformation through the one or more perforations.

Another embodiment of the present invention is a method of a reducingfluid loss from a perforated interval of a well bore comprising:providing a treatment fluid comprising an aqueous fluid and a fluid losscontrol additive comprising a water-soluble polymer having hydrophobicor hydrophilic modification; introducing the treatment fluid into theperforated interval of the well bore so that the treatment fluidcontacts a portion of a subterranean formation through one or moreopenings that extend from the perforated interval of the well bore intothe subterranean formation.

Another embodiment of the present invention is a method of reducingfluid loss from a gravel packed interval of a well bore comprising:providing a treatment fluid comprising an aqueous fluid and a fluid losscontrol additive comprising a water-soluble polymer having hydrophobicor hydrophilic modification; introducing the treatment fluid into thegravel packed interval of the well bore, wherein a gravel pack isdisposed in the gravel packed interval of the well bore, and wherein thetreatment fluid contacts the gravel pack.

Other and further features and advantages of the present invention willbe readily apparent to those skilled in the art upon a reading of thedescription of the preferred embodiments that follows.

BRIEF DESCRIPTION OF THE FIGURES

These figures illustrate certain aspects of some of the embodiments ofthe present invention, and should not be used to limit or define theinvention.

FIG. 1 is a cross-sectional side view of a well bore illustrating oneembodiment of the present invention.

FIG. 2 is a cross-sectional side view of a well bore illustrating aperforated interval in accordance with one embodiment of the presentinvention.

FIG. 3 is a cross-sectional side view of a well bore illustrating agravel packed interval in accordance with one embodiment of the presentinvention.

FIG. 4 is a plot of fluid loss volume per time for a dynamic fluid losstest performed using a round cell containing a H.P. Berea sandstone coreand various sample fluids.

FIG. 5 is a plot of fluid loss volume per time for a dynamic fluid losstest performed using a round cell containing a L.P. Berea sandstone coreand various sample fluids.

FIG. 6 is a plot of fluid loss volume per time for a dynamic fluid losstest performed using a round cell containing an Ohio sandstone core andvarious sample fluids.

FIG. 7 is a plot of fluid loss volume per time for a dynamic fluid losstest performed using a round cell containing a H.P. Berea sandstone coreand various sample fluids.

FIG. 8 is a plot of fluid loss volume per time for a dynamic fluid losstest performed using a round cell containing a L.P. Berea sandstone coreand various sample fluids.

FIG. 9 is a plot of fluid loss volume per time for a dynamic fluid losstest performed using a round cell containing an Ohio sandstone core andvarious sample fluids.

FIG. 10 is a plot of fluid loss volume versus time for a fluid loss testperformed using Berea sandstone core and various sample fluids.

FIG. 11 is a plot of fluid loss volume versus time for a fluid loss testperformed using a Berea sandstone core and various sample fluids.

FIG. 12 is a plot of fluid loss volume versus time for a fluid loss testperformed using a Berea sandstone core and various sample fluids.

DESCRIPTION OF PREFERRED EMBODIMENTS

The present invention relates to subterranean treatments and, moreparticularly, to using fluid loss control additives that comprise awater-soluble polymer having hydrophobic or hydrophilic modification. Asused herein, “water-soluble” refers to at least 0.01 weight percentsoluble in distilled water. As used herein, the phrase “hydrophobicallymodified,” or “hydrophobic modification,” refers to the incorporationinto the hydrophilic polymer structure of hydrophobic groups, whereinthe alkyl chain length is from about 4 to about 22 carbons. As usedherein, the phrase “hydrophilically modified,” or “hydrophilicmodification,” refers to the incorporation into the hydrophilic polymerstructure of hydrophilic groups, such as to introduce branching or toincrease the degree of branching in the hydrophilic polymer. The methodsand compositions of the present invention may be utilized in horizontal,vertical, inclined, or otherwise formed portions of wells.

The treatment fluids of the present invention generally comprise anaqueous fluid and a fluid loss control additive that comprises awater-soluble polymer having hydrophobic or hydrophilic modification. Avariety of additional additives suitable for use in the chosen treatmentmay be included in the treatment fluids as desired. The aqueous fluid ofthe treatment fluids of the present invention may include freshwater,saltwater, brine (e.g., saturated saltwater), or seawater. Generally,the aqueous fluid may be from any source, provided that it does notcontain components that may adversely affect other components in thetreatment fluid.

Generally, the fluid loss control additives used in the treatment fluidsof the present invention comprise a water-soluble polymer havinghydrophobic or hydrophilic modification. A water-soluble polymer withhydrophobic modification is referred to herein as “hydrophobicallymodified.” A water-soluble polymer with hydrophilic modification isreferred to herein as “hydrophilically modified.” Among other things thefluid loss control additives should reduce fluid loss from the treatmentfluid or any other aqueous fluids subsequently introduced into the wellbore. It is believed that after contact with surfaces within theformation's flow paths, at least a portion of the water-soluble polymershould attach to the surfaces, thereby reducing the permeability of thesubterranean formation to aqueous fluids without substantially changingits permeability to hydrocarbons.

The hydrophobically modified polymers useful in the present inventiontypically have molecular weights in the range of from about 100,000 toabout 10,000,000. While these hydrophobically modified polymers havehydrophobic groups incorporated into the hydrophilic polymer structure,they should remain water-soluble. In some embodiments, a mole ratio of ahydrophilic monomer to the hydrophobic compound in the hydrophobicallymodified polymer is in the range of from about 99.98:0.02 to about90:10, wherein the hydrophilic monomer is a calculated amount present inthe hydrophilic polymer. In certain embodiments, the hydrophobicallymodified polymers may comprise a polymer backbone that comprises polarheteroatoms. Generally, the polar heteroatoms present within the polymerbackbone of the hydrophobically modified polymers include, but are notlimited to, oxygen, nitrogen, sulfur, or phosphorous.

The hydrophobically modified polymers may be synthesized utilizing anysuitable method. In one example, the hydrophobically modified polymersmay be a reaction product of a hydrophilic polymer and a hydrophobiccompound. In another example, the hydrophobically modified polymers maybe prepared from a polymerization reaction comprising a hydrophilicmonomer and a hydrophobically modified hydrophilic monomer. Those ofordinary skill in the art, with the benefit of this disclosure, will beable to determine other suitable methods for the synthesis of suitablehydrophobically modified polymers.

In certain embodiments, suitable hydrophobically modified polymers maybe synthesized by the hydrophobic modification of a hydrophilic polymer.The hydrophilic polymers suitable for forming the hydrophobicallymodified polymers used in the present invention should be capable ofreacting with hydrophobic compounds. Suitable hydrophilic polymersinclude, homo-, co-, or terpolymers such as, but not limited to,polyacrylamides, polyvinylamines, poly(vinylamines/vinyl alcohols),alkyl acrylate polymers in general, and derivatives thereof. Additionalexamples of alkyl acrylate polymers include, but are not limited to,polydimethylaminoethyl methacrylate, polydimethylaminopropylmethacrylamide, poly(acrylamide/dimethylaminoethyl methacrylate),poly(methacrylic acid/dimethylaminoethyl methacrylate),poly(2-acrylamido-2-methyl propane sulfonic acid/dimethylaminoethylmethacrylate), poly(acrylamide/dimethylaminopropyl methacrylamide), poly(acrylic acid/dimethylaminopropyl methacrylamide), and poly(methacrylicacid/dimethylaminopropyl methacrylamide). In certain embodiments, thehydrophilic polymers comprise a polymer backbone and reactive aminogroups in the polymer backbone or as pendant groups, the reactive aminogroups capable of reacting with hydrophobic compounds. In someembodiments, the hydrophilic polymers comprise dialkyl amino pendantgroups. In some embodiments, the hydrophilic polymers comprise adimethyl amino pendant group and a monomer comprising dimethylaminoethylmethacrylate or dimethylaminopropyl methacrylamide. In certainembodiments of the present invention, the hydrophilic polymers comprisea polymer backbone that comprises polar heteroatoms, wherein the polarheteroatoms present within the polymer backbone of the hydrophilicpolymers include, but are not limited to, oxygen, nitrogen, sulfur, orphosphorous. Suitable hydrophilic polymers that comprise polarheteroatoms within the polymer backbone include homo-, co-, orterpolymers, such as, but not limited to, celluloses, chitosans,polyamides, polyetheramines, polyethyleneimines, polyhydroxyetheramines,polylysines, polysulfones, gums, starches, and derivatives thereof. Inone embodiment, the starch is a cationic starch. A suitable cationicstarch may be formed by reacting a starch, such as corn, maize, waxymaize, potato, and tapioca, and the like, with the reaction product ofepichlorohydrin and trialkylamine.

The hydrophobic compounds that are capable of reacting with thehydrophilic polymers of the present invention include, but are notlimited to, alkyl halides, sulfonates, sulfates, organic acids, andorganic acid derivatives. Examples of suitable organic acids andderivatives thereof include, but are not limited to, octenyl succinicacid; dodecenyl succinic acid; and anhydrides, esters, imides, andamides of octenyl succinic acid or dodecenyl succinic acid. In certainembodiments, the hydrophobic compounds may have an alkyl chain length offrom about 4 to about 22 carbons. In another embodiment, the hydrophobiccompounds may have an alkyl chain length of from about 7 to about 22carbons. In another embodiment, the hydrophobic compounds may have analkyl chain length of from about 12 to about 18 carbons. For example,where the hydrophobic compound is an alkyl halide, the reaction betweenthe hydrophobic compound and hydrophilic polymer may result in thequaternization of at least some of the hydrophilic polymer amino groupswith an alkyl halide, wherein the alkyl chain length is from about 4 toabout 22 carbons.

As previously mentioned, in certain embodiments, suitablehydrophobically modified polymers also may be prepared from apolymerization reaction comprising a hydrophilic monomer and ahydrophobically modified hydrophilic monomer. Examples of suitablemethods of their preparation are described in U.S. Pat. No. 6,476,169,the relevant disclosure of which is incorporated herein by reference.The hydrophobically modified polymers synthesized from thepolymerization reactions may have estimated molecular weights in therange of from about 100,000 to about 10,000,000 and mole ratios of thehydrophilic monomer(s) to the hydrophobically modified hydrophilicmonomer(s) in the range of from about 99.98:0.02 to about 90:10.

A variety of hydrophilic monomers may be used to form thehydrophobically modified polymers useful in the present invention.Examples of suitable hydrophilic monomers include, but are not limitedto acrylamide, 2-acrylamido-2-methyl propane sulfonic acid,N,N-dimethylacrylamide, vinyl pyrrolidone, dimethylaminoethylmethacrylate, acrylic acid, dimethylaminopropylmethacrylamide, vinylamine, vinyl acetate, trimethylammoniumethyl methacrylate chloride,methacrylamide, hydroxyethyl acrylate, vinyl sulfonic acid, vinylphosphonic acid, methacrylic acid, vinyl caprolactam, N-vinylformamide,N,N-diallylacetamide, dimethyldiallyl ammonium halide, itaconic acid,styrene sulfonic acid, methacrylamidoethyltrimethyl ammonium halide,quaternary salt derivatives of acrylamide, and quaternary saltderivatives of acrylic acid.

A variety of hydrophobically modified hydrophilic monomers also may beused to form the hydrophobically modified polymers useful in the presentinvention. Examples of suitable hydrophobically modified hydrophilicmonomers include, but are not limited to, alkyl acrylates, alkylmethacrylates, alkyl acrylamides, alkyl methacrylamides alkyldimethylammoniumethyl methacrylate halides, and alkyldimethylammoniumpropyl methacrylamide halides, wherein the alkyl groupshave from about 4 to about 22 carbon atoms. In another embodiment, thealkyl groups have from about 7 to about 22 carbons. In anotherembodiment, the alkyl groups have from about 12 to about 18 carbons. Incertain embodiments, the hydrophobically modified hydrophilic monomercomprises octadecyldimethylammoniumethyl methacrylate bromide,hexadecyldimethylammoniumethyl methacrylate bromide,hexadecyldimethylammoniumpropyl methacrylamide bromide, 2-ethylhexylmethacrylate, or hexadecyl methacrylamide.

Suitable hydrophobically modified polymers that may be formed from theabove-described reactions include, but are not limited to,acrylamide/octadecyldimethylammoniumethyl methacrylate bromidecopolymer, dimethylaminoethyl methacrylate/vinylpyrrolidone/hexadecyldimethylammoniumethyl methacrylate bromideterpolymer, and acrylamide/2-acrylamido-2-methyl propane sulfonicacid/2-ethylhexyl methacrylate terpolymer. Another suitablehydrophobically modified polymer formed from the above-describedreaction comprises an amino methacrylate/alkylammonium methacrylatecopolymer. A suitable dimethlyaminoethylmethacrylate/alkyl-dimethylammoniumethyl methacrylate copolymer is adimethylaminoethyl methacrylate/hexadecyl-dimethylammoniumethylmethacrylate copolymer. As previously discussed, these copolymers may beformed by reactions with a variety of alkyl halides. For example, insome embodiments, the hydrophobically modified polymer may comprise adimethylaminoethyl methacrylate/hexadecyl-dimethylammoniumethylmethacrylate bromide copolymer.

In another embodiment of the present invention, the fluid loss controladditives of the present invention may comprise a water-solublehydrophilically modified polymer. The hydrophilically modified polymersof the present invention typically have molecular weights in the rangeof from about 100,000 to about 10,000,000. In certain embodiments, thehydrophilically modified polymers comprise a polymer backbone thatcomprises polar heteroatoms. Generally, the polar heteroatoms presentwithin the polymer backbone of the hydrophilically modified polymersinclude, but are not limited to, oxygen, nitrogen, sulfur, orphosphorous.

The hydrophilically modified polymers may be synthesized utilizing anysuitable method. In one example, the hydrophilically modified polymersmay be a reaction product of a hydrophilic polymer and a hydrophiliccompound. Those of ordinary skill in the art, with the benefit of thisdisclosure, will be able to determine other suitable methods for thepreparation of suitable hydrophilically modified polymers.

In certain embodiments, suitable hydrophilically modified polymers maybe formed by additional hydrophilic modification, for example, tointroduce branching or to increase the degree of branching, of ahydrophilic polymer. The hydrophilic polymers suitable for forming thehydrophilically modified polymers used in the present invention shouldbe capable of reacting with hydrophilic compounds. In certainembodiments, suitable hydrophilic polymers include, homo-, co-, orterpolymers, such as, but not limited to, polyacrylamides,polyvinylamines, poly(vinylamines/vinyl alcohols), and alkyl acrylatepolymers in general. Additional examples of alkyl acrylate polymersinclude, but are not limited to, polydimethylaminoethyl methacrylate,polydimethylaminopropyl methacrylamide,poly(acrylamide/dimethylaminoethyl methacrylate), poly(methacrylicacid/dimethylaminoethyl methacrylate), poly(2-acrylamido-2-methylpropane sulfonic acid/dimethylaminoethyl methacrylate),poly(acrylamide/dimethylaminopropyl methacrylamide), poly (acrylicacid/dimethylaminopropyl methacrylamide), and poly(methacrylicacid/dimethylaminopropyl methacrylamide). In certain embodiments, thehydrophilic polymers comprise a polymer backbone and reactive aminogroups in the polymer backbone or as pendant groups, the reactive aminogroups capable of reacting with hydrophilic compounds. In someembodiments, the hydrophilic polymers comprise dialkyl amino pendantgroups. In some embodiments, the hydrophilic polymers comprise adimethyl amino pendant group and at least one monomer comprisingdimethylaminoethyl methacrylate or dimethylaminopropyl methacrylamide.In other embodiments, the hydrophilic polymers comprise a polymerbackbone that comprises polar heteroatoms, wherein the polar heteroatomspresent within the polymer backbone of the hydrophilic polymers include,but are not limited to, oxygen, nitrogen, sulfur, or phosphorous.Suitable hydrophilic polymers that comprise polar heteroatoms within thepolymer backbone include homo-, co-, or terpolymers, such as, but notlimited to, celluloses, chitosans, polyamides, polyetheramines,polyethyleneimines, polyhydroxyetheramines, polylysines, polysulfones,gums, starches, and derivatives thereof. In one embodiment, the starchis a cationic starch. A suitable cationic starch may be formed byreacting a starch, such as corn, maize, waxy maize, potato, tapioca, andthe like, with the reaction product of epichlorohydrin andtrialkylamine.

The hydrophilic compounds suitable for reaction with the hydrophilicpolymers include polyethers that comprise halogens, sulfonates,sulfates, organic acids, and organic acid derivatives. Examples ofsuitable polyethers include, but are not limited to, polyethyleneoxides, polypropylene oxides, and polybutylene oxides, and copolymers,terpolymers, and mixtures thereof. In some embodiments, the polyethercomprises an epichlorohydrin-terminated polyethylene oxide methyl ether.

The hydrophilically modified polymers formed from the reaction of ahydrophilic polymer with a hydrophilic compound may have estimatedmolecular weights in the range of from about 100,000 to about 10,000,000and may have weight ratios of the hydrophilic polymers to the polyethersin the range of from about 1:1 to about 10:1. Suitable hydrophilicallymodified polymers having molecular weights and weight ratios in theranges set forth above include, but are not limited to, the reactionproduct of polydimethylaminoethyl methacrylate andepichlorohydrin-terminated polyethyleneoxide methyl ether; the reactionproduct of polydimethylaminopropyl methacrylamide andepichlorohydrin-terminated polyethyleneoxide methyl ether; and thereaction product of poly(acrylamide/dimethylaminopropyl methacrylamide)and epichlorohydrin-terminated polyethyleneoxide methyl ether. In someembodiments, the hydrophilically modified polymer comprises the reactionproduct of a polydimethylaminoethyl methacrylate andepichlorohydrin-terminated polyethyleneoxide methyl ether having aweight ratio of polydimethylaminoethyl methacrylate toepichlorohydrin-terminated polyethyleneoxide methyl ether of about 3:1.

Sufficient concentrations of the fluid loss control additives of thepresent invention should be present in the treatment fluids of thepresent invention to provide the desired level of fluid loss control. Insome embodiments, the fluid loss control additives should be present inthe treatment fluids of the present invention in an amount in the rangeof from about 0.02% to about 10% by weight of the treatment fluid. Inanother embodiment, the fluid loss control additive should be present inthe treatment fluids of the present invention in an amount in the rangeof from about 0.05% to about 1.0% by weight of the treatment fluid. Incertain embodiments of the present invention, the fluid loss controladditive may be provided in a concentrated aqueous solution prior to itscombination with the other components necessary to form the treatmentfluids of the present invention.

Additional additives may be added to the treatment fluids of the presentinvention as deemed appropriate for a particular application by oneskilled in the art with the benefit of this disclosure. Examples of suchadditives include, but are not limited to, weighting agents,surfactants, scale inhibitors, antifoaming agents, bactericides, salts,foaming agents, acids, conventional fluid loss control additives,viscosifying agents, crosslinking agents, gel breakers, shale swellinginhibitors, combinations thereof, and the like.

The treatment fluids of the present invention may be used insubterranean formations where it is desirable to provide fluid losscontrol. Generally, the fluid loss control additives may be used at anystage of a subterranean treatment. In certain embodiments, the treatmentfluid may be a drilling fluid, a fracturing fluid, a workover fluid, awell bore cleanup fluid, a gravel packing fluid, or any other suitableaqueous fluid used in subterranean treatments. In another embodiment,the treatment fluids may be a fluid loss control pill that is introducedinto the well bore at any stage of the subterranean treatment. Forexample, the treatment fluid may be a preflush that is introduced intothe well bore prior to the subterranean treatment.

Generally, the methods of the present invention comprise introducing atreatment fluid of the present invention that comprises an aqueous fluidand a fluid loss control additive that comprises a water-soluble polymerhaving hydrophobic or hydrophilic modification into a well bore thatpenetrates a subterranean formation so as to reduce fluid loss into atleast a portion of the subterranean formation from the treatment fluidor another aqueous fluid introduced into the well bore subsequent to thetreatment fluid. Generally, at least a portion of the treatment fluidshould penetrate into the porosity of at least a portion of thesubterranean formation at least some depth from the treated surface. Itis believed that the water-soluble polymer present in the portion of thetreatment fluid in contact with formation should attach to surfaceswithin the porosity of the portion of the subterranean formation. Thepresence of the water-soluble polymers therein should reduce thepermeability of the treated portion of the subterranean formation toaqueous fluids without substantially changing the permeability thereofto subsequently produced or injected hydrocarbon fluids. This shouldreduce fluid loss into the treated portion from the treatment fluidand/or any other aqueous fluids (e.g., workover fluids, completionfluids, cleanup fluids, fracturing fluids, gravel packing fluids,drilling fluids, etc.) subsequently introduced into the well bore. Forexample, the methods of the present invention may be useful to controlfluid loss during subsequent entry and/or removal of completionequipment into the well bore. In addition, the water-soluble polymersalso may reduce subsequent problems associated with water flowing intothe well bore from the treated portion of the subterranean formation.

Among other things, subsequent remedial treatments should not berequired to remove the water-soluble polymers prior to placing the wellinto production. If desired, however, oxidizers may be used to removethe water-soluble polymer. For example, it may be desired, in someinstances, to remove the water-soluble polymers so that fluidssubsequently introduced into the formation can enter the formation.Examples of suitable oxidizers include, but are not limited to, alkali,alkaline earth, and transition metal salts of periodate, hypochlorite,perbromate, chlorite, chlorate; hydrogen peroxide; manganese peroxide;peracetic acid; and combinations thereof.

Referring to FIG. 1, well 100 is illustrated. Well 100 comprises wellbore 102 that penetrates subterranean formation 104. Even though FIG. 1depicts well bore 102 as a vertical well bore, the methods of thepresent invention may be suitable for use in generally horizontal,generally vertical, or otherwise formed portions of wells. Casing 106may be disposed in well bore 102, as shown in FIG. 1, or, in someembodiments, well bore 102 may be open hole. In some embodiments, casing106 may extend from the ground surface (not shown) into well bore 102.In some embodiments, casing 106 may be connected to the ground surface(not shown) by intervening casing (not shown), such as surface casingand conductor pipe. Casing 106 may or may not be cemented tosubterranean formation with cement sheath 108.

Perforating tool 110 in accordance with one embodiment of the presentinvention, is shown disposed in well bore 102 on tubing 111. Perforatingtool 110 may be conveyed into well bore 102 using any suitablemethodology. For example, perforating tool 110 may be conveyed into wellbore on coiled tubing, jointed tubing, drill pipe, a slickline, anelectric line, casing, and the like. In some embodiments, perforatingtool 110 may be fixed in place at the bottom of well bore 102 with a gunhanger. As indicated in FIG. 1, perforating tool 110 may be positionedin well bore 102 so that it is adjacent to a portion of subterraneanformation 104. Perforating tool 110 may be any suitable device used toperforate wells, including, but not limited to, perforating guns, laserperforating devices, chemical perforating devices, hydraulic jettingdevices, or any other suitable device. Once perforating tool 110 hasbeen positioned in well bore 102 at the location to be perforated,perforations 112 that communicate with subterranean formation 104 may becreated using perforating tool 110. Any suitable method may be used toactivate perforating tool 110. For example, perforating tool 110 may beactivated by pressure, pressure pulsing, remote acoustic telemetry,mechanically, electronic signal, or any other suitable methodology.Perforations 112 extend from well bore 102 into the portion ofsubterranean formation 104 adjacent thereto. In the cased embodiments,as shown in FIG. 1, perforations 112 extend from well bore 102, throughcasing 106 and cement sheath 108, and into subterranean formation 104.

In accordance with the methods of the present invention, a treatmentfluid of the present invention that comprise an aqueous fluid and afluid loss control additive that comprise a water-soluble polymer havinghydrophobic or hydrophilic modification may be introduced into theinterval of well bore 102 to be perforated. The treatment fluid may beintroduced into well bore 102 before or after perforating tool 110 hasbeen positioned in well bore 102. In some embodiments, the treatmentfluid may surround perforating tool 110 in well bore 102. The treatmentfluid may be introduced into well bore 102 before or after perforations112 have been created using perforating tool 110. Treatment fluid shouldcontact subterranean formation 104 through perforations 112. It isbelieved that after contact with subterranean formation 104, thewater-soluble polymer having hydrophobic or hydrophilic modificationshould attach to surfaces within the porosity of subterranean formation104, thereby reducing the permeability of subterranean formation 104 toaqueous fluids without substantially changing its permeability tohydrocarbons. This reduction in permeability to aqueous fluid shouldreduce fluid loss from well bore 102 through perforations 112.

In some embodiments, the interval of well bore 102 may be underbalancedin that the pressure of the interval of well bore 102 to be perforatedis less than the pressure in the portion of subterranean formation 104adjacent thereto. A treatment fluid of the present invention may beintroduced into the interval of well bore 102 to be perforated prior toor after the creation of perforations 112. After creation ofperforations 112, well bore 102 may be put into an overbalancedcondition so that the treatment fluid may contact subterranean formation104 through perforations 112. In these underbalanced conditions, aftercreation of perforations 112, formation fluid may enter well bore 102through perforations 112. In some embodiments, a treatment fluid of thepresent invention may be introduced into well bore 102 at a pressuresufficient to at least substantially displace the formation fluid fromwell bore 102.

In some embodiments, the interval of well bore 102 may be overbalancedin that the pressure of the interval of well bore 102 to be perforatedexceeds the pressure in the portion of subterranean formation 104adjacent thereto. In these overbalanced embodiments, after creation ofperforations 112, the treatment fluid of the present invention shouldcontact subterranean formation 104 through perforations 112. In theseoverbalanced embodiments, the treatment fluid of the present inventionmay be introduced into the interval of well bore 102 to be perforatedprior to the creation of perforations 112.

In some overbalanced embodiments, extreme overbalanced perforating maybe performed. Extreme overbalanced perforating involves increasing thepressure of well bore 102 inside casing 106 to a pressure much higherthan the pressure in the portion of subterranean formation 104 adjacentthereto using a cushion of expandable gas in well bore 102, such asnitrogen. In these extreme overbalanced embodiments, after creation ofperforations 112, the extreme pressure in well bore 102 results in asurge of fluid from well bore 102 into subterranean formation 104through perforations 112 at a pressure sufficient to induce one or moresmall fractures in subterranean formation 104. These small fractures maybe capable of bypassing near well bore damage. In the extremeoverbalanced embodiments, the water-soluble polymer should controladditional losses of fluid to subterranean formation 104 after theinitial surge of the treatment fluid through perforations 112 tominimize longer term fluid loss into subterranean formation 104.

Another method suitable for achieving an extreme overbalanced conditionin well bore 102 comprises the use of propellant sleeves comprising apropellant material on perforating tool 110. Where perforating tool 110is a perforating gun, the propellant material may be ignited by thefiring of perforating tool 110, and the combustion of this propellantmaterial generates a localized pressure surged in well bore 102generated by the combustions of gases released by the propellantmaterial. Due to this pressure surge, there should be rapid fluid lossesof the treatment fluid through perforations 112 into subterraneanformation 104 allowing one or more fractures to form in subterraneanformation that extend beyond any near well bore damage surroundingperforations 112. In these embodiments, the water-soluble polymer shouldcontrol additional losses of fluid to subterranean formation 104 afterthe initial surface of the treatment fluid through perforations 112 tominimize longer term fluid loss into subterranean formation 104.

In some embodiments, the interval of well bore 102 may be balanced inthat the pressure of the interval of well bore 102 to be perforated isabout equal to the pressure in the portion of subterranean formation 104adjacent thereto. In these balanced embodiments, after creation ofperforations 112, the treatment fluid of the present invention shouldcontact subterranean formation 104 through perforations 112. In thesebalanced embodiments, the treatment fluid of the present invention maybe introduced into the interval of well bore 102 to be perforated priorto the creation of perforations 112.

In some overbalanced and balanced embodiments, immediately aftercreation of perforations 112, the pressure of the interval of well bore102 that has been perforated is less than the pressure in the portion ofsubterranean formation 104 adjacent thereto. This is commonly referredto as “dynamic underbalance.” The dynamic underbalance may be createdusing any suitable methodology, including the use of a chamber in theperforating tool. In these dynamic underbalanced embodiments, theunderbalanced condition of well bore 102 is temporary. In these dynamicunderbalanced conditions, formations fluid should enter well bore 102after creation of perforations due to the underbalanced condition thathas been created in well bore 102. In some embodiments, a treatmentfluid of the present invention may have been introduced into theinterval of well bore 102 to be perforated prior to the creation ofperforations 118. Because the underbalanced condition of well bore 102is temporary, once the overbalanced or balanced condition returns, thetreatment fluid of the present invention should contact subterraneanformation 104 through perforations 118.

Referring to FIG. 2, well 200 is illustrated. Well 200 contains wellbore 202 that penetrates subterranean formation 204. Even though FIG. 2depicts well bore 202 as a vertical well bore, the methods of thepresent invention may be suitable for use in generally horizontal,generally vertical, or otherwise formed portions of wells. Casing 206may be disposed in well bore 202, as shown in FIG. 2, or, in someembodiments, well bore 202 may be open hole. In some embodiments, casing206 may extend from the ground surface (not shown) into well bore 202.In some embodiments, casing 206 may be connected to the ground surface(not shown) by intervening casing (not shown), such as surface casingand conductor pipe. Casing 206 may or may not be cemented tosubterranean formation with cement sheath 208.

Well bore 202 further contains perforated interval 210. Perforatedinterval 210 comprises perforations 212 in communication withsubterranean formation 202. Perforations 212 extend from well bore 202into the portion of subterranean formation 204 adjacent thereto. In thecased embodiments, as shown in FIG. 2, perforations 212 extend from wellbore 202, through casing 206 and cement sheath 208, and intosubterranean formation 204. While perforated interval 210 is depictedhaving perforations 212 therein, the term “perforated interval” as usedherein refers to any portion of a well bore having one or more openingstherein through which fluid may be lost into a subterranean formation.For example, in some embodiments, a perforated interval may contain oneor more holes formed due to casing failure and/or casing wear.

In accordance with the methods of the present invention, a treatmentfluid of the present invention comprising an aqueous fluid and a fluidloss control additive that comprises a water-soluble polymer havinghydrophobic or hydrophilic modification may be introduced intoperforated interval 210 of well bore 202. The treatment fluid shouldcontact the portion of subterranean formation 204 adjacent to perforatedinterval 210 through perforations 212. It is believed that thewater-soluble polymer having hydrophobic or hydrophilic modificationshould attach to surfaces within the porosity of subterranean formation204, thereby reducing the permeability of subterranean formation 204without substantially changing its permeability to hydrocarbons. Thisreduction in permeability to aqueous fluid should reduce fluid loss fromthe well bore 202 in perforated interval 210.

Referring to FIG. 3, well 300 is illustrated. Well 300 contains wellbore 302 that penetrates subterranean formation 304. Even though FIG. 3depicts well bore 302 as a vertical well bore, the methods of thepresent invention may be suitable for use in generally horizontal,generally vertical, or otherwise formed portions of wells. Casing 306may be disposed in well bore 302, as shown in FIG. 3, or, in someembodiments, well bore 302 may be open hole. In some embodiments, casing306 may extend from the ground surface (not shown) into well bore 302.In some embodiments, casing 306 may be connected to the ground surface(not shown) by intervening casing (not shown), such as surface casingand conductor pipe. Casing 306 may or may not be cemented tosubterranean formation with cement sheath 308.

Well bore 302 further contains gravel packed interval 310. Gravel packedinterval 310 contains perforations 312 in communication withsubterranean formation 304. Perforations 312 extend from well bore 302into the portion of subterranean formation 304 adjacent thereto. In thecased embodiments, as shown in FIG. 3, perforations 312 extend from wellbore 302, through casing 306, and cement sheath 308, and intosubterranean formation 304.

Sand control screen 314 is shown disposed in well bore 302. Annulus 316is formed between sand control screen 314 and casing 306. Even thoughFIG. 3 depicts a sand control screen, the methods of the presentinvention may be used with a variety of suitable sand control equipment,including screens, liners (e.g., slotted liners, perforated liners,etc.), combinations of screens and liners, and any other suitableapparatus. Sand control screen 314 may be a wire-wrapped or expandablescreen or any other suitable sand control screen. Gravel pack 318 isshown disposed in well bore 302. Gravel pack 318 comprises gravelparticulates that have been packed in annulus 316 between sand controlscreen 314 and casing 306.

In accordance with the methods of the present invention a treatmentfluid of the present invention that comprises an aqueous fluid and afluid loss control additive that comprises a water-soluble polymerhaving hydrophobic or hydrophilic modification may be introduced intogravel packed interval 310 of well bore 302 so as to contact gravel pack318. It is believed that the water-soluble polymer having hydrophobic orhydrophilic modification should attach to surfaces within gravel pack318 in the gravel packed interval, thereby reducing the permeability ofgravel pack 318 to aqueous fluids without substantially changing itspermeability to hydrocarbons. This reduction in permeability to aqueousfluids should reduce fluid loss from well bore 302 through gravel pack318.

To facilitate a better understanding of the present invention, thefollowing examples of some of the preferred embodiments are given. In noway should the following examples be read to limit, or to define, thescope of the invention.

EXAMPLES Example 1

A fluid loss control additive useful in the present invention wasprepared by mixing 47.7 grams (“g”) of deionized water, 0.38 g of(n-hexadecyl) dimethylammonium ethyl methacrylate bromide, and 1.1 g ofacrylamide, and sparging with nitrogen for approximately 30 minutes.Thereafter, a polymerization initiator, such as 0.0127 g of 2,2′-azobis(2-amidinopropane)dihydrochloride was added. The resulting solutionwas then heated, with stirring, to 112° F. and held for 18 hours toproduce a highly viscous polymer solution.

Example 2

A fluid loss control additive useful in the present invention wasprepared by mixing 41.2 g of deionized water, 0.06 g of octadecylmethacrylate, 0.45 g of cocoamidopropyl betaine surfactant, and 1.26 gof acrylamide. Thereafter, a polymerization initiator, such as 0.0127 gof 2,2′-azo bis(2-amidinopropane)dihydrochloride was added. Theresulting solution was then heated, with stirring, to 112° F. and heldfor 18 hours to produce a highly viscous polymer solution.

Example 3

A fluid loss control additive useful in the present invention wasprepared as follows. First, a polymer was prepared by mixing 1,968 g ofdeionized water, 105 g of dimethylaminoethyl methacrylate and spargingwith nitrogen for 30 minutes. Thereafter, the pH was adjusted toapproximately 7.9 with sulfuric acid and a polymerization initiator,such as 0.46 g of 2,2′-azo bis(2-amidinopropane)dihydrochloride wasadded. The resulting solution was then heated, with stirring, to 112° F.and held for 18 hours to produce poly(dimethylaminoethyl methacrylate).

The poly(dimethylaminoethyl methacrylate) was then hydrophobicallymodified by adding 71.0 g of it to a 250 ml round flask, followed by 15%NaOH to achieve a pH of approximately 8.9. Next, 54.6 g of water, 0.36 gof C16 alkyl (n-hexadecyl) bromide, and 0.39 g ofbenzylcetyldimethylammonium bromide surfactant were added to quatemizethe poly(dimethylaminoethyl methacrylate)homopolymer and form adimethylaminoethyl methacrylate/hexadecyl-dimethylammoniumethylmethacrylate copolymer. This mixture was then heated, with stirring, to140° F. and held for 24 hours to produce a highly viscous polymersolution.

Example 4

Fluid loss control tests (Tests Nos. 1-2) were performed using a hollowBerea sandstone core with the following dimensions: 2.75-inch length,2.5-inch outer diameter, 1-inch inner diameter. The Berea sandstone corewas mounted in a cell in which fluids can be pumped through the core intwo directions. In one direction, defined as the “production direction,”fluid is flowed from the exterior of the core, through the core, andinto the hollow interior. Fluid also may be flowed in the directionopposite the production direction so that fluid is flowed from thehollow interior of the core, through the core, and to the exterior ofthe core. Fluid flowing opposite the production direction representsfluid loss from a well bore into the formation. Two treatment solutionswere prepared for this series of tests.

The sample treatment fluid used in Test No. 1 (comparative) was a brinecontaining 21% potassium chloride by weight. Test No. 1 was performed atroom temperature.

The sample treatment fluid used in Test No. 2 was prepared by adding0.2% of a fluid loss control additive by weight to a brine containing21% potassium chloride by weight. Accordingly, the sample treatmentfluid used in Test No. 2 comprised 21% of potassium chloride by weightand 0.2% of a fluid loss control additive by weight. The fluid losscontrol additive was a dimethylaminoethylmethacrylate/hexadecyl-dimethylammoniumethyl methacrylate copolymerprepared as described in Example 3. Test No. 2 was performed at roomtemperature.

The following procedure was used for this series of tests. For eachtest, the core experienced a flow sequence of 1) brine, 2) oil(kerosene), 3) drilling mud (to build a filter cake), 4) sampletreatment fluid, 5) oil (kerosene). The first flow step, brine, was inthe production direction and prepared the core for the test. The brineused in the first flow step was a brine containing 7% potassium chlorideby weight. Next, in the second flow step, the kerosene was flowed in theproduction direction at a constant rate until the pressure stabilized,and the initial permeability of the core was calculated. Thereafter, inthe third flow step, a sample drilling mud was placed in the hollowinterior of the core and pressure was applied, such that a drillingfluid filter cake was formed on the inner surface of the core. Afterformation of the drilling fluid filter cake, the sample treatment fluidwas placed in the inner hole, and a constant pressure of 120 psi wasapplied. The filtrate loss from the sample treatment fluid was thenmeasured as a function of time. In the fifth flow step, kerosene wasflowed in the production direction at the same rate and the finalpermeability of the core was calculated. For each series of tests, theinitial and final permeability of the core to kerosene was essentiallyunchanged. Table 1 contains the data for this series of tests.

TABLE 1 Filtrate Loss (ml) at Given Time (hours) Polymer 1 3 5 6.2 7 7.67.9 8.3 Test Concentration hr hrs hrs hrs hrs hrs hrs hrs No. 1 0 1.72.3 3.2 3.6 10 31 50 80 @ room temperature No. 2 2000 ppm 1.7 2.3 3.23.6 3.9 4.1 4.3 4.4 @ room temperature

Accordingly, this example indicates that the above-described fluid losscontrol additives that comprise hydrophobically modified polymers may beuseful for controlling fluid loss from a well bore into a subterraneanformation.

Example 5

Permeability reduction tests (Test Nos. 3-4) were performed using twotreatment solutions and a multipressure tap Hassler sleeve containing aBrown sandstone core. The Hassler sleeve contained three pressure taps,as well as an inlet and an outlet for determining pressure, therebydividing the core into four segments. Test No. 3 was performed at 150°F., and Test No. 4 was performed at 175° F.

The sample treatment fluid used in Test No. 3 was prepared by adding0.6% of a fluid loss control additive by weight to a 2% by weightpotassium chloride (“KCl”) brine. Thus, the sample treatment fluid usedin Test No. 3 comprised 2% of KCl by weight and 0.6% of a fluid losscontrol additive by weight. The fluid loss control additive was adimethylaminoethyl methacrylate/hexadecyl-dimethylammoniumethylmethacrylate copolymer prepared as described in Example 3.

The sample treatment fluid used in Test No. 4 was prepared by adding0.2% of a fluid loss control additive by weight to a 2% by weight KClbrine. Thus, the sample treatment fluid used in Test No. 4 comprised 2%of KCl by weight and 0.2% of a fluid loss control additive by weight.The fluid loss control additive was a dimethylaminoethylmethacrylate/hexadecyl-dimethylammoniumethyl methacrylate copolymerprepared as described in Example 3.

The following procedure was used for this series of tests. For eachtest, the core experienced a flow sequence of 1) brine, 2) oil(kerosene), 3) brine, 4) sample treatment fluid, 5) brine. The brineused in flow steps 1, 3, and 5 was a brine containing 7% potassiumchloride by weight. The first two flow steps of brine and oil preparedthe core for the test. The brine flow in step 3 was maintained until thepressure stabilized, yielding an initial permeability for the core,listed in Tables 2 and 3 below as “Initial Core Permeability.” Next, 15ml of the sample treatment fluid were flowed into the core. Next, thebrine flow was reestablished until the pressure stabilized to determinethe permeability of the core after treatment with the sample treatmentfluid, listed in Tables 2 and 3 below as “Final Core Permeability.”Initial and Final Core Permeabilities were utilized to determine apercent reduction of water permeability according to the followingformula:% Reduction of Water Permeability=(1−Final Permeability/InitialPermeability)×100

As previously discussed, the multipressure tap Hassler Sleeve dividedthe core into four segments. For the above-described tests, flow steps1, 2, 3, and 5 were from segment 1 to segment 4, and flow step 4 wasfrom segment 4 to segment 1. The results of Test No. 3 utilizing apolymer concentration of 6,000 ppm are provided in Table No. 2 below.

TABLE 2 Initial Core Final Core Permeability Permeability % Reduction of(mDarcy) (mDarcy) Water Permeability Segment 1 371.7 328.59 12 Segment 2303.56 20.08 93 Segment 3 358.92 30.27 92 Segment 4 96.19 1.69 98 Total241.46 8.36 97

The results of Test No. 4 utilizing a polymer concentration of 2,000 ppmare provided in Table No. 3 below.

TABLE 3 Initial Core Final Core Permeability Permeability % Reduction of(mDarcy) (mDarcy) Water Permeability Segment 1 2,059.79 823.65 60Segment 2 4,372.98 1,784.29 59 Segment 3 283.76 1.74 99 Segment 45,281.94 4.81 100 Total 722.01 4.43 99

Accordingly, Example 5 indicates that the fluid loss control additivesuseful in the present invention that comprise hydrophobically modifiedpolymers may be useful for controlling fluid loss from a well bore intoa subterranean formation.

Example 6

A permeability reduction test (Test No. 5) was performed using twotreatment solutions and a multipressure tap Hassler sleeve containing aBrown sandstone core. The Hassler sleeve contained three pressure taps,as well as an inlet and an outlet for determining pressure), therebydividing the core into four segments.

The sample treatment fluid used in Test No. 5 was prepared by adding0.2% of a fluid loss control additive by weight to a 2% by weight KClbrine. Thus, the sample treatment fluid used in Test No. 5 comprised 2%of KCl by weight and 0.2% of a fluid loss control additive by weight.The fluid loss control additive was a dimethylaminoethylmethacrylate/hexadecyl-dimethylammoniumethyl methacrylate copolymerprepared as described in Example 3. Test No. 5 was performed at 150° F.

The following procedure was used for this test. The core experienced aflow sequence of 1) brine, 2) oil (kerosene), 3) sample treatment fluid,4) oil (kerosene). The first flow step of brine prepared the core forthe test. The brine used in flow step 1 was a brine containing 7% KCl byweight. The oil flow in step 2 was maintained until the pressurestabilized, yielding an initial permeability for the core, listed inTables 2 and 3 below as “Initial Core Permeability.” Next, the sampletreatment fluid was flowed into the core. Next, the oil flow wasreestablished until the pressure stabilized to determine thepermeability of the core after treatment with the sample treatmentfluid, listed in Tables 2 and 3 below as “Final Core Permeability.”Initial and Final Core Permeabilities were utilized to determine apercent reduction of oil permeability according to the followingformula:% Reduction of Oil Permeability=(1−Final Permeability/InitialPermeability)×100

As previously discussed, the multipressure tap Hassler Sleeve dividedthe core into four segments. For the above-described tests, flow stepsNos. 1, 2, and 4 were from segment 1 to segment 4, and flow step No. 3was from segment 4 to segment 1. The results of Test No. 5 utilizing apolymer concentration of 2,000 ppm are provided in Table No. 4 below.

TABLE 4 Initial Core Final Core Permeability Permeability % Reduction ofOil (mDarcy) (mDarcy) Permeability Total 3,571.5 4,725.25 −32

Accordingly, this example indicates that the above-described fluid losscontrol additives that comprise hydrophobically modified polymers maynot damage the permeability of hydrocarbon-bearing formations.

Example 7

A fluid loss control additive useful in the present invention wasprepared as follows. First, a polymer was prepared by mixing 45.0 g ofdimethylaminoethyl methacrylate, 6.8 g acrylic acid, 372.0 g of waterand sparging with nitrogen for 30 minutes. Thereafter, the pH wasadjusted to approximately 5.3 with 5.7 mL of concentrated sulfuric acid,followed by the addition of 0.2 mL of 2-mercaptoethanol and 1.3 g of2,2′-azo bis(2-amidinopropane)dihydrochloride. The resulting solutionwas then heated to 71° C., with stirring, and held for 18 hours toproduce poly(dimethylaminoethyl methacrylate/acrylic acid).

The poly(dimethylaminoethyl methacrylate/acrylic acid) was thenhydrophilically modified by adding 95.0 g of the polymer to a 250 mLroundbottom flask, followed by the addition of 5.7 g of a 65% solutionof an epichlorohydrin-terminated polyethylene oxide methyl ether and 8.0g of sodium chloride. Approximately 17 mL of 3% active sodium hydroxidesolution was then added to reach a pH of approximately 8.2. The mixturewas then heated, with stirring, to 71° C. The viscosity of the solutionwas monitored, and when the viscosity reached 2000 centipoise (asmeasured with a Brookfield LVT viscometer, #2 spindle at 12 rpm, 25° C.)the reaction was terminated by removing the heat source and adding 5 mLof 17% hydrochloric acid, 2.0 g sodium chloride and 14.7 g water.

Example 8

Dynamic fluid loss control tests (Test Nos. 6-11) were performed usingfour sample fluids and a round cell containing a formation core sample.High Pressure (“HP”) Berea Sandstone, Low Pressure (“LP”) BereaSandstone, and Ohio Sandstone core samples were used for this series oftests.

The following procedure was used for this series of tests. The formationcore samples were cut for a round core holder and placed into the coreholder. The round core holder used a 1.5-inch diameter core. There was a0.16-inch gap to allow fluid flow through the cell and across the coreface for the dynamic test conditions. The round cells were heated to140° F.

After the round cells were prepared, the sample fluid was pumped through340 feet of 0.194-inch I.D. tubing to provide preconditioning and shearhistory for the fluid. The shear rate was approximately 440 sec⁻¹ at apump rate of 0.31 l/min. After exiting this tubing, the sample fluid waspumped into a 0.402-inch I.D. tubing section (112 feet) that wasimmersed in a heating bath. This simulated the lower shear rate of fluidflow in a fracture. The shear rate was about 50 sec⁻¹. For this seriesof test, the sample fluid was heated to 140° F. as it flowed throughthis tubing section. After exiting this tubing section, the sample fluidwas forced through the heated round cells where the dynamic fluid lossoccurred. The gap for fluid flow in the round cell created the sameshear rate (50 sec⁻¹ as in the previous tubing section. A 1,000-psipressure differential drives fluid loss through the formation coresample. The fluid loss test was continued for the desired length of timewhile fluid loss volumes were collected.

Sample Fluid No. 1 (comparative) was a WaterFrac™ 25 fluid system havinga gelling agent concentration of 25 pounds per thousand gallons(lbs/mgal). WaterFrac™ 25 is a fluid system that is commerciallyavailable from Halliburton Energy Services, Inc., Duncan, Okla. SampleFluid No. 1 was prepared by adding 25 lbs/mgal of WG-22™ gelling agentto a base fluid. WG-22™ is a guar-based gelling agent that iscommercially available from Halliburton Energy Services, Inc., Duncan,Okla. The base fluid was water that contained 2% KCl by weight. SampleFluid No. 1 had a pH of 8.01. The viscosity of Sample Fluid No. 1 wasfound to be 17 cP at 74.1° F. on a Fann® Model 35 Viscometer ⅕ spring at300 rpm.

Sample Fluid No. 2 was prepared by adding 67 gallons per thousandgallons (gal/mgal) of a fluid loss control additive to the WaterFrac™ 25fluid system of Sample Fluid No. 1. The fluid loss control additive wasa dimethylaminoethyl methacrylate/hexadecyl-dimethylammoniumethylmethacrylate copolymer prepared as described in Example 3. Next, thesample was buffered to a pH of 6.09 using BA-20™ buffering agent, whichis commercially available from Halliburton Energy Services, Inc.,Duncan, Okla. The viscosity of Sample Fluid No. 2 was found to be 19.7cP at 74.1° F. on a Fann® Model 35 Viscometer ⅕ spring at 300 rpm.

Sample Fluid No. 3 (comparative) was a Delta Frac® 140 25 fluid systemhaving a gelling agent concentration of 25 lbs/mgal. Delta Frac® 140 25is a fluid system that is commercially available from Halliburton EnergyServices, Inc., Duncan, Okla. Sample No. 2 was prepared by adding 25lbs/mgal of WG-22™ gelling agent to a base fluid. WG-22™ is a guar-basedgelling agent that is commercially available from Halliburton EnergyServices, Inc., Duncan, Okla. The base fluid was water that contained 2%KCl by weight. The base gel had a pH of 7.72. The viscosity of the basegel was found to be 16.1 cP at 72.3° F. on a Fann® Model 35 Viscometer ⅕spring at 300 rpm. Next, 2 gals/mgal of BC-2 crosslinking agent wasadded to the base gel. BC-2 is a borate crosslinking agent that iscommercially available from Halliburton Energy Services, Inc., Duncan,Okla. Next, 0.0017 gals/mgal of N-Zyme 3™ breaking agent was added tothe base gel. N-Zyme 3™ is a breaking agent that is commerciallyavailable from Halliburton Energy Services, Inc., Duncan, Okla. Thegelled and crosslinked Sample Fluid No. 3 had a pH of 8.55.

Sample Fluid No. 4 was prepared by adding 67 gal/mgal of a fluid losscontrol additive to the Delta Frac® 140 25 fluid system of Sample FluidNo. 3. The fluid loss control additive was a dimethylaminoethylmethacrylate/hexadecyl-dimethylammoniumethyl methacrylate copolymerprepared as described in Example 3. Sample Fluid No. 4 had a pH of 8.54.The viscosity of Sample Fluid No. 4 was found to be 16.2 cP at 74.1° F.on a Fann® Model 35 Viscometer ⅕ spring at 300 rpm.

Dynamic fluid loss control tests (Test No. 6) were conducted inaccordance with the above procedure using the H.P. Berea sandstone coresample for both Sample Fluid No. 1 and Sample Fluid No. 2. Table 5 belowlists the total fluid loss volume after 4 minutes for each sample. Theresults of this test are also depicted in FIG. 4.

TABLE 5 H.P. BEREA SANDSTONE CORE Fluid Loss Control Total Fluid LossAdditive After 4 Minutes Fluid (gals/mgal) (ml/cm²) Sample Fluid No. 1 086.76 (WaterFrac ™ 25 Fluid System) Sample Fluid No. 2 67 24.69(WaterFrac ™ 25 Fluid System)

Dynamic fluid loss control tests (Test No. 7) were conducted inaccordance with the above procedure using the L.P. Berea sandstone coresamples for both Sample Fluid No. 1 and Sample Fluid No. 2. Table 6below lists the total fluid loss volume after 1 hour for each sample.The results of this test are also depicted in FIG. 5.

TABLE 6 L.P. BEREA SANDSTONE CORE Fluid Loss Control Total Fluid LossAdditive After 1 Hour Fluid (gals/mgal) (ml/cm²) Sample Fluid No. 1 039.46 (WaterFrac ™ 25 Fluid System) Sample Fluid No. 2 67 3.42(WaterFrac ™ 25 Fluid System)

Dynamic fluid loss control tests (Test No. 8) were conducted inaccordance with the above procedure using the Ohio sandstone core samplefor both Sample Fluid No. 1 and Sample Fluid No. 2. Table 7 below liststhe total fluid loss volume after 1 hour for each sample. The results ofthis test are also depicted in FIG. 6.

TABLE 7 OHIO SANDSTONE CORE Fluid Loss Control Total Fluid Loss AdditiveAfter 1 Hour Fluid (gals/mgal) (ml/cm²) Sample Fluid No. 1 0 1.25(WaterFrac ™ 25 Fluid System) Sample Fluid No. 2 67 1.18 (WaterFrac ™ 25Fluid System)

In addition to the above tests for Sample Fluid No. 1 and No. 2, dynamicfluid loss control tests (Test No. 9) were also conducted in accordancewith the above procedure for Sample Fluid No. 3 and No. 4 on each of theformation core samples. First, the dynamic fluid loss tests wereconducted using the H.P. Berea sandstone core sample. Table 8 belowlists the total fluid loss volume after 1 hour for each sample. Theresults of this test are also depicted in FIG. 7.

TABLE 8 H.P. BEREA SANDSTONE CORE Fluid Loss Control Total Fluid LossAdditive After 1 Hour Fluid (gals/mgal) (ml/cm²) Sample Fluid No. 3 04.13 (Delta Frac ® 140 25 Fluid System) Sample Fluid No. 4 67 2.51(Delta Frac ® 140 25 Fluid System)

Dynamic fluid loss control tests (Test No. 10) were conducted inaccordance with the above procedure using the L.P. Berea sandstone coresamples for both Sample Fluid No. 3 and Sample Fluid No. 4. Table 9below lists the total fluid loss volume after 1 hour for each sample.The results of this test are also depicted in FIG. 8.

TABLE 9 L.P. BEREA SANDSTONE CORE Fluid Loss Control Total Fluid LossAdditive After 1 Hour Fluid (gals/mgal) (ml/cm²) Sample Fluid No. 3 01.83 (Delta Frac ® 140 25 Fluid System) Sample Fluid No. 4 67 1.16(Delta Frac ® 140 25 Fluid System)

Dynamic fluid loss control tests (Test No. 11) were conducted inaccordance with the above procedure using the Ohio sandstone core samplefor both Sample Fluid No. 3 and Sample Fluid No. 4. Table 10 below liststhe total fluid loss volume after 1 hour for each sample. The results ofthis test are also depicted in FIG. 9.

TABLE 10 OHIO SANDSTONE CORE Fluid Loss Control Total Fluid LossAdditive After 1 Hour Fluid (gals/mgal) (ml/cm²) Sample Fluid No. 1 01.84 (WaterFrac ™ 25 Fluid System) Sample Fluid No. 2 67 1.33(WaterFrac ™ 25 Fluid System)

Accordingly, this Example illustrates that the fluid loss controladditives useful in the present invention may be suitable for providingdynamic fluid loss control in a variety of formation rock types andfluid systems.

Example 9

Fluid loss control tests (Tests Nos. 12-13) were performed using ahollow Berea sandstone core with the following dimensions: 2.75-inchlength, 2.5-inch outer diameter, 1-inch inner diameter. The Bereasandstone core was mounted in a cell in which fluids can be pumpedthrough the core in two directions. In one direction, defined as the“production direction,” fluid is flowed from the exterior of the core,through the core, and into the hollow interior. Fluid also may be flowedin the direction opposite the production direction so that fluid isflowed from the hollow interior of the core, through the core, and tothe exterior of the core. Fluid flowing opposite the productiondirection represents fluid loss from a well bore into the formation. Twotreatment solutions were prepared for this series of tests.

The following procedure was used for this series of tests. For eachtest, the core experienced a flow sequence of 1) brine, 2) oil(kerosene), 3) drilling mud (to build a filter cake), and 4) sampletreatment fluid. The first flow step, brine, was in the productiondirection and prepared the core for the test. The brine used in thefirst flow step was a brine containing 7% potassium chloride by weight.Next, in the second flow step, the kerosene was flowed in the productiondirection at a constant rate until the pressure stabilized. Thereafter,in the third flow step, a sample drilling mud was placed in the hollowinterior of the core and pressure was applied, such that a drillingfluid filter cake was formed on the inner surface of the core. Afterformation of the drilling fluid filter cake, the sample treatment fluidwas placed in the inner hole, and a constant pressure of 120 psi wasapplied. The filtrate loss from the sample treatment fluid was thenmeasured as a function of time.

The sample treatment fluid used in Test No. 12 was prepared by adding0.2% by weight of a fluid loss control additive to an aqueous fluid thatcomprised 10% acetic acid by weight and 1% HC-2 by weight. HC-2 is anamphoteric surfactant from Halliburton Energy Services, Inc. The fluidloss control additive was a dimethylaminoethylmethacrylate/hexadecyl-dimethylammoniumethyl methacrylate copolymerprepared as described in Example 3. Test No. 12 was performed using thisfluid at room temperature and at 170° F. Test No. 12 was also performedusing this sample treatment fluid that comprised 10% acetic acid byweight and 1% HC-2 by weight without the fluid loss control additive.The results of Test No. 12 are provided in FIG. 10.

The sample treatment fluid used in Test No. 13 was prepared by adding0.2% by weight of a fluid loss control additive to a 21% by weight KClbrine. The fluid loss control additive was a dimethylaminoethylmethacrylate/hexadecyl-dimethylammoniumethyl methacrylate copolymerprepared as described in Example 3. Test No. 13 was performed using thisfluid at room temperature. This test was repeated using the 21% KClbrine without the fluid loss control additive. The results of Test No.13 are provided in FIG. 11.

Accordingly, this Example illustrates that the fluid loss controladditives useful in the present invention may be suitable for providingfluid loss control.

Example 10

Fluid loss control test (Test No. 14) was performed using a hollow Bereasandstone core with the following dimensions: 2.75-inch length, 2.5-inchouter diameter, 1-inch inner diameter. The Berea sandstone core wasmounted in a cell in which fluids can be pumped through the core in twodirections. In one direction, defined as the “production direction,”fluid is flowed from the exterior of the core, through the core, andinto the hollow interior. Fluid also may be flowed in the directionopposite the production direction so that fluid is flowed from thehollow interior of the core, through the core, and to the exterior ofthe core. Fluid flowing opposite the production direction representsfluid loss from a well bore into the formation.

The following procedure was used for this series of tests. For eachtest, the core experienced a flow sequence of 1) brine, 2) oil(kerosene), 3) drilling mud (to build a filter cake), and 4) sampletreatment fluid. The first flow step, brine, was in the productiondirection and prepared the core for the test. The brine used in thefirst flow step was a brine containing 7% potassium chloride by weight.Next, in the second flow step, the kerosene was flowed in the productiondirection at a constant rate until the pressure stabilized. Thereafter,in the third flow step, a sample drilling mud was placed in the hollowinterior of the core and pressure was applied, such that a drillingfluid filter cake was formed on the inner surface of the core. Afterformation of the drilling fluid filter cake, the cell was opened up andpacked with 40/60 mesh sand. Thereafter, the sample treatment fluid wasplaced in the inner hole, and a constant pressure of 120 psi wasapplied. The filtrate loss from the sample treatment fluid was thenmeasured as a function of time.

The sample treatment fluid used in Test No. 14 was prepared by adding0.2% by weight of a fluid loss control additive to an aqueous fluid thatcomprised 10% acetic acid by weight and 1% HC-2 by weight. The fluidloss control additive was a dimethylaminoethylmethacrylate/hexadecyl-dimethylammoniumethyl methacrylate copolymerprepared as described in Example 3. Test No. 14 was performed using thisfluid at 170° F. This test was repeated using this sample treatmentfluid that comprised 10% acetic acid by weight and 1% HC-2 by weightwithout the fluid loss control additive. The results of Test No. 14 areprovided in FIG. 12.

Accordingly, this Example illustrates that the fluid loss controladditives useful in the present invention may be suitable for providingfluid loss control.

Therefore, the present invention is well adapted to carry out theobjects and attain the ends and advantages mentioned as well as thosethat are inherent therein. While numerous changes may be made by thoseskilled in the art, such changes are encompassed within the spirit andscope of this invention as defined by the appended claims. The terms inthe claims have their plain, ordinary meaning unless otherwise definedby the patentee.

1. A method of controlling fluid loss in a subterranean formationcomprising: providing a treatment fluid comprising an aqueous fluid anda fluid loss control additive comprising a water-soluble polymer havinghydrophobic modification, wherein the water-soluble polymer comprises apolymer backbone that comprises polar heteroatoms, and wherein thewater-soluble polymer comprises at least one hydrophobically modifiedpolymer that comprises a reaction product between a hydrophobic compoundand a hydrophilic polymer wherein the hydrophobic compound is selectedfrom the group consisting of: an anhydride of octenyl succinic acid; anester of octenyl succinic acid, an amide of octenyl succinic acid, ananhydride of dodecenyl succinic acid, an ester of dodecenyl succinicacid, and an amide of dodecenyl succinic acid and wherein thehydrophilic polymer comprises a reactive amino group in the polymerbackbone or as a pendant group, the reactive amino group capable ofreacting with the hydrophobic compound; and introducing the treatmentfluid into an interval of a well bore penetrating the subterraneanformation wherein the water-soluble polymer reduces the permeability ofthe portion of the subterranean formation to aqueous fluids withoutsubstantially reducing the permeability to hydrocarbons so that fluidloss from the aqueous fluid into the portion of the subterraneanformation is reduced; creating one or more perforations in the intervalof the well bore, wherein the perforations extend from the well bore andinto the subterranean formation; and allowing the treatment fluid tocontact a portion of the subterranean formation through the one or moreperforations.
 2. The method of claim 1 wherein pressure in the intervalof the well is overbalanced, underbalanced, or balanced.
 3. The methodof claim 1 wherein pressure in the interval of the well bore isoverbalanced, and the treatment fluid contacts the subterraneanformation so as to create one or more fractures therein.
 4. The methodof claim 1 wherein the treatment fluid is introduced into the intervalof the well bore at a pressure sufficient to at least substantiallydisplace formation fluid from the well bore, the formation fluid havingentered the well bore through the one or more perforations.
 5. Themethod of claim 1 wherein the step of introducing the treatment fluidinto the interval of the well bore occurs after the step of creating theone or more perforations.
 6. The method of claim 1 wherein the step ofcreating one or more perforations utilizes a perforating gun, a laserperforating device, a chemical perforating device, or a hydraulicjetting device.
 7. The method of claim 1 wherein the step of creatingthe one or more perforations creates a dynamic underbalance in theinterval of the well bore.
 8. The method of claim 1 further comprisingthe step of: introducing an oxidizer into the interval of the well boreso as to contact the portion of the subterranean formation, subsequentto the step of allowing the treatment fluid to contact the portion ofthe subterranean formation.
 9. The method of claim 1 wherein thewater-soluble polymer is selected from the group consisting of: achitosan; a polyamide; a polyetheramine; a polyethyleneimine; apolyhydroxyetheramine; a polylysine; and derivatives thereof.
 10. Amethod of reducing fluid loss from a perforated interval of a well borecomprising: providing a treatment fluid comprising an aqueous fluid anda fluid loss control additive comprising a water-soluble polymer havinghydrophobic modification, wherein the water-soluble polymer comprises apolymer backbone that comprises polar heteroatoms, and wherein thewater-soluble polymer comprises at least one hydrophobically modifiedpolymer that comprises a reaction product between a hydrophobic compoundand a hydrophilic polymer wherein the hydrophobic compound is selectedfrom the group consisting of: an anhydride of octenyl succinic acid; anester of octenyl succinic acid, an amide of octenyl succinic acid, ananhydride of dodecenyl succinic acid, an ester of dodecenyl succinicacid, and an amide of dodecenyl succinic acid and wherein thehydrophilic polymer comprises a reactive amino group in the polymerbackbone or as a pendant group, the reactive amino group capable ofreacting with the hydrophobic compound; and introducing the treatmentfluid into the perforated interval of the well bore so that thetreatment fluid contacts a portion of a subterranean formation throughone or more openings that extend from the perforated interval of thewell bore into the subterranean formation wherein the water-solublepolymer reduces the permeability of the portion of the subterraneanformation to aqueous fluids without substantially reducing thepermeability to hydrocarbons so that fluid loss from the aqueous fluidinto the portion of the subterranean formation is reduced.
 11. Themethod of claim 10 wherein the one or more openings extend from the wellbore, through a casing that is disposed in the well bore, and into theportion of the subterranean formation.
 12. The method of claim 11wherein the one or more openings are selected from the group consistingof: perforations in the casing; openings created in the casing by casingfailure; openings created in the casing by casing wear; and combinationsthereof.
 13. The method of claim 10 wherein pressure in the interval ofthe well bore is overbalanced, and the treatment fluid contacts thesubterranean formation so as to create one or more fractures therein.14. The method of claim 10 wherein the treatment fluid is introducedinto the interval of the well bore at a pressure sufficient to at leastsubstantially displace formation fluid from the well bore, the formationfluid having entered the well bore through the one or more perforations.15. The method of claim 10 further comprising the step of: introducingan oxidizer into the interval of the well bore so as to contact theportion of the subterranean formation, subsequent to the step ofintroducing the treatment fluid to the perforated interval of the wellbore.
 16. The method of claim 10 wherein the water-soluble polymer isselected from the group consisting of: a chitosan; a polyamide; apolyetheramine; a polyethyleneimine; a polyhydroxyetheramine; apolylysine; and derivatives thereof.
 17. A method of reducing fluid lossfrom a gravel packed interval of a well bore comprising: providing atreatment fluid comprising an aqueous fluid and a fluid loss controladditive comprising a water-soluble polymer having hydrophobicmodification, wherein the water-soluble polymer comprises a polymerbackbone that comprises polar heteroatoms, and wherein the water-solublepolymer comprises at least one hydrophobically modified polymercomprising a reaction product of a reaction comprising a hydrophobiccompound selected from the group consisting of: an anhydride of octenylsuccinic acid; an ester of octenyl succinic acid, an amide of octenylsuccinic acid, an anhydride of dodecenyl succinic acid, an ester ofdodecenyl succinic acid, and an amide of dodecenyl succinic acid and ahydrophilic polymer; and, introducing the treatment fluid into at leasta portion of a gravel pack disposed in the well bore wherein thewater-soluble polymer reduces the permeability of the gravel pack toaqueous fluids without substantially reducing the permeability tohydrocarbons.
 18. The method of claim 17 further comprising the step of:introducing an oxidizer into the interval of the well bore so as tocontact the portion of the subterranean formation, subsequent to thestep of introducing the treatment fluid into at least a portion of agravel pack.
 19. The method of claim 17 wherein the water-solublepolymer is selected from the group consisting of: a chitosan; apolyamide; a polyetheramine; a polyethyleneimine; apolyhydroxyetheramine; a polylysine; and derivatives thereof.